Efficient combined cycle power plant with co2 capture and a combustor arrangement with separate flows

ABSTRACT

The invention relates to a method for inter alia to increase the energy and cost efficiency of a gas power plant or a thermal heat plant with CO 2  capturing. The power plant comprises gas turbine plants ( 12,12 ′) comprising compressor units ( 13,13 ′) and turbine units ( 14,14 ′) and further comprises a combustor ( 10 ). The combustor ( 10 ) is working in principle with to separate gas part streams where one gas part stream flows internally through the flame tube ( 40 ) of the combustor ( 10 ), while the other gas part stream is flowing along the exterior of the flame tube ( 40 ). The first gas part stream comprises additional air and re-circulated, un-cleaned flue gas from the combustor ( 10 ), said gases being combusted together with fuel inside the flame tube ( 40 ). The second gas part stream comprises cleaned flue gas which is heated up at the exterior of the flame tube ( 40 ) while the flame tube ( 40 ) is cooled down. The invention comprises also a power plant, a combustor and a CO 2  capture plant.

FIELD OF INVENTION

The present invention relates generally to a method for increasing the energy and cost efficiency of a gas power plant or a thermal power plant with a plant for CO₂ capture. The invention relates further to a gas power plant or a thermal power plant. In particular the invention relates to integration of one or more combined cycle gas turbines and a CO₂ exhaust gas cleaning plant, adapted to pressurized flue gas with enriched CO₂ content. The invention relates also to a modified combustor.

BACKGROUND OF THE INVENTION

During the last decades there has been a substantial global increase in the amount of carbon dioxide (CO₂) emission to atmosphere. According to the Kyoto agreement and based on the precautionary principle it is important to reduce the emission of climate gases such as CO₂ in order to counteract changes in climate. One way is to capture CO₂ when converting energy from fossil fuel in a gas power plant and/or thermal power plant. The different elements in the CO₂ value chain include technology for CO₂ capture, transportation of and finally final storage or exploitation of CO₂, for example for increased oil recovery from the oil reservoir (IOR).

The technology development within the field of CO₂ capture from combustion processes may be divided into three main categories, wherein the following feasible and useable technology is:

-   -   Removal of CO₂ prior to combustion (hydrogen power plant—Pre         Combustion Type);     -   Removal of CO₂ subsequent to combustion (exhaust gas         cleaning—Post Combustion Type), and     -   Stoichiometric combustion of natural gas and oxygen (oxy-fuel         type).

Of the three main categories, the exhaust gas cleaning technology is the most developed technology, and there exists plants running on an intermediate scale. Exhaust gas cleaning has still a cost reduction potential and may most quickly be tested in a pilot plant.

The present technology for exhaust gas cleaning is based on absorption of carbon subsequent to combustion. A gas power plant of this type is disclosed in the prior art literature, textbooks and publications.

Emission of CO₂ may usually be reduced by 85-90% compared to a plant without any exhaust gas cleaning system. The exhaust gases from a standard combined cycle gas turbine plant contain ca. 3.5 volume % of CO₂ and the exhaust gas must be cooled down to normal operation temperature for amine washing, such temperature being approximately 40-44° C. In an atmospheric adsorption tower the CO₂ in the gas is transferred to the liquid phase by chemical absorption in the amine liquid. It is imperative to have a large area of contact between the gas and the liquid. Consequently, the tower may have to be as high as 30 metres or more. For a gas power plant of 400 MW the volume of exhaust gas to be cleaned is in the order of 2.500.000 Nm³/hr, and the required cross sectional area of the absorption column will be 260-320 m².

In the regenerating plant the CO₂ is removed from the amine liquid by heating the mixture up to 120-125° C. Steam from the gas power plant is used both for heating, diluting and transportation of CO₂ out of the plant. Subsequent to cooling and condensation, CO₂ and water is separated, using a desorption column in order to obtain mass transfer from liquid to steam. The desorption column may have a height of ca. 20 metres and having a cross sectional area of 60-150 m².

The amine liquid solution may then be re-used for absorption subsequent to retrieval of heat from the liquid solution and reduction of the temperature. The desorption process produces a waste which has to be handled separately. For a 400 MW gas power plant said waste represents approximately 90-1500 tonnes/year, out of which 30-500 tonnes/year are amines, salts and organic carbon. The regeneration process requires substantial amount of energy, resulting in a reduction in efficiency of approximately 20% for a standard gas power plant producing electricity. A standard gas power plant having this type of exhaust gas cleaning means has thus the disadvantage that both investment costs and running costs are significantly high. In addition, such plants require large areas.

More cost effective CO₂ capture plants are known for other type of utilization, such as for example for CO₂ capture from a well stream from a natural gas field, e.g. the Sleipner field in the North Sea or from synthesis gas production. The operation of such plants are, however, subjected to completely different conditions of operation, i.e. higher pressure and/or higher CO₂ content, compared to exhaust gas cleaning from plants commonly operating at atmospheric pressure and with low CO₂ content of approximately 3.5 volume %.

In the North Sea there exists production platforms using an amine absorption plant and a desorption plant, but such CO₂ capturing plants are of a substantially smaller size, less costly and requiring less energy to operate.

Further it is known to use CO₂ membranes, for example of the polymer type, for pressurized well streams and process gases in plants, especially in USA. Said plants are even more energy- and cost effective. Contrary to the amine plants the CO₂ membrane plants require no liquid parts and consequently no regeneration of liquid, thereby avoiding the requirement for additional energy.

Another advantage of amine plants is the feasibility of operating at a higher temperature, typical 40-100° C. in the CO₂ membrane plant. A certain leakage flow of N₂ may escape through the CO₂ membrane, and N₂ may be removed subsequent to being compressed to a pressure where CO₂ is transformed to liquid, allowing N₂ to be separated. In case of injection into an oil reservoir for increasing the oil recovery it may not necessary to separate N₂ and CO₂. In certain cases it may be advantageous to maintain a mixture of N₂ and CO₂ in order to increase oil recovery.

Capturing plants of the amine type for exhaust gas having CO₂ enriched content and/or at a higher pressure are disclosed in several documents, such as for example WO 95/21683 or WO 00/57900.

In order to obtain lower NO_(x) emission from incinerators, it is proposed to recycle cooled flue gas by means of a booster fan back to the combustor.

SUMMARY OF THE INVENTION

An object of the invention is to provide a power plant from which emission of climate gases and detrimental gases from an environmental point of view, such as amines, salts, etc. is reduced to a minimum or eliminated.

Another object is to obtain more energy- and cost effective solutions and to reduce, preferably bisect, both costs of investment and cost of operation compared to state of art technology. It is of particular interest to arrive at energy effective solutions in which the temperature at the inlet of the turbine is as high as possible. In addition a favourable and improved heat transfer in the combustor is obtained, hence transferring the high-quality heat energy to the that part of the gas stream which is led to the turbine.

It is also an object to obtain cost effective solutions for gas power plant, corresponding to the ones used for example for capturing CO₂ from the well stream from the natural gas field, by applying a new capturing means for exhaust gas with enriched volume of CO₂ and a higher pressure.

According to the invention the objects are obtained by using a method; a power plant and a combustor as further described in the in the encompassing claims.

According to the invention a more efficient power plant is obtained, where the emissions of CO₂ may be reduced by preferably 85-90%, although lower reduction, e.g. 0-90%, may be achieved.

Further, a more simplified plant, not requiring large areas or footprints compared to the prior art amine washing solutions, is achieved, mainly since the CO₂ membrane has a simplified construction and is not dependent upon a washing unit for separating CO₂ from the liquid. An effective exploitation of such CO₂ membrane solution, for example of the polymer type, for cleaning of flue gas requires that the flue gas both is pressurized and is enriched of CO₂.

A further advantage according to the invention is that the need for large gas-gas heat exchangers may be reduced or completely eliminated. It may be difficult to construct such large heat exchangers for temperatures exceeding 600 C.° without using cost extensive solutions and expensive materials.

According to the invention a cost effective heating in the combustor is achieved. Injection of steam in one of the gas streams prior to heating in the combustor may further contribute positively since the specific heat capacity of steam is higher than the heat capacity of air. Further, injection of steam contributes substantially to maintaining the effect of the turbine at a high level by compensating for the volume of CO₂ removed in the CO₂ membrane plant. As a consequence of the invention the following is achieved:

-   -   Higher degree of efficiency due to higher temperature at the         turbine inlet.     -   It is possible to separate CO₂ by means of a polymer membrane.     -   It is feasible to inject steam in one or more of the gas stream         parts.     -   It is feasible to employ a semi-closed gas turbine cycle and a         high CO₂ content, since the combustor may receive both         compressed air and recycled flue gas, thereby achieving stable         combustion of natural gas.     -   Produce low formation of NO_(x) since the combustor receives         both fresh air and recycled flue gas, thus working at an optimal         combustion temperature.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in details below, referring to the drawings, wherein:

FIG. 1 shows a schematic diagram of the principle applied to a preferred embodiment of a gas power plant according to the invention, where the gas power plant is provided with a combustor employing separate gas streams according to the invention, the gas power plant being of the combined cycle gas turbine power plant (CCGT power plant);

FIG. 2 shows an improved combustor plant according to the invention;

FIG. 3 shows a further embodiment of a combustor plant;

FIG. 4 shows details of a preferred embodiment of the combustor applied in the combustor plant.

DESCRIPTION OF THE EMBODIMENTS

The process shown in principle and in a schematic manner in FIG. 1 comprises a gas power plant or a thermal power plant based in principle on a power plant part A in the form of a combined cycle gas turbine plant and an integrated CO₂ capture plant B, for example a CO₂ membrane plant 11 intended to separate CO₂ from pressurized flue gas having CO₂ enriched content, delivered from the combustor 10. The CO₂ capture plant 11 may be of the amine system type.

Two integrated gas turbine plants 12,12′ are used, depending on common combustor(s) 10 and operating in principle with two separate gas streams, one gas stream consisting of un-purified flue gas and one stream consisting inter alia of purified flue gas. The gas turbine plant 12′ may for example be of the semi-closed type. The combustor 10 comprises a flame tube 40 and a surrounding casing or jacket 27. The combustor 10 and its manner of operation will be described in further detail referring to FIGS. 2-4.

One or more boilers or heat recovery steam generators (HRSG) 17,18 are included in the power plant part A, together with heat exchangers 19 and for example generators 20,21 for production of electricity.

As indicated in FIG. 1 natural gas is introduced into the plant together with air and produced, cleaned exhaust or flue gas, free of CO₂ while CO₂ and energy, for example in the form of electricity, is produced in the plant. The flue gas is led into the CO₂ capture plant 11 at a pressure equal to or larger than 15 bar and with a CO₂ concentration preferably exceeding 10%. The flue gas is discharged out of the plant A at least substantially clean of CO₂.

The CO₂ extracted in the CO₂ capture plant 11 may for example be used to increase oil recovery from a reservoir (IOR).

FIG. 2 shows a preferred embodiment of a combined cycle gas turbine plant and a CO₂ recovery plant 11. The gas turbine plant comprises a first gas turbine 12 comprising a compressor 13, a turbine 14 and a generator 21, operating on a common shaft. The compressor 13 delivers pressurized air to a flame tube 40 in a combustor 10 through a pipe 15. The air has a temperature of approx. 400° C. and has a pressure in the order of 15 bar. Further, fuel in the form of natural gas is injected into the flame tube 40. The flue gas from the flame tube 40 drives the turbine 14′ of a second gas turbine 12′. The temperature of the flue gas leaving the combustor 10 may typically be in the order of 1200-1400° C., such temperatures being common inlet temperature for turbines of advanced gas turbines. For such solutions it is preferred that the distance between the combustor 10 and the inlet of the turbine 14′ is short, thereby reducing the use of expensive high temperature resistant materials. Reference is made to FIGS. 1 and 2.

From the turbine 14′, the flue gas having a temperature in the order of 500° C., is fed to a heat recovery steam generator 18 in which the flue gas is cooled down. The flue gas leaves the heat recovery steam generator 18 at a temperature in the order of 100° C. and is led to a water cooler 16, a means for separating out water 22 and a booster or a compressor unit 23, whereupon the pressurized flue gas is led to the inlet of the compressor 13′ of the second gas turbine 12′, compressing flue gas. The water separated out in the water separator 22 is then reintroduced in the gas stream from the booster 23 in order to regulate the mole weight of the gas at the inlet of the compressor 13′. If too little or too much water is separated in the water separator 22, water may be removed or added from an external source (not shown).

After the compressor 13′ the pressurized flue gas is split into two part streams, one part stream going via a simple heat exchanger 19 to the CO₂ capture plant 11. The cleaned flue gas is led back via the heat exchanger 19 and into the jacket 27 surrounding the flame tube 40. After the cleaned flue gas having circulated through the jacket 27 the flue gas is led to the turbine 14 of the first gas turbine 12 through the pipe 29. This gas flow has a typical temperature of approximately 800-1000° C. or higher. From the turbine 14 the cleaned flue gas is led through a pipe 30 to a second heat recovery steam generator 17 for production of steam by means of the heat recovered from the cleaned flue gas, prior to discharging the flue gas to the atmosphere.

The second gas stream from the exit of the compressor 13′ of the second gas turbine 12′ is re-circulated through a recirculation pipe 24 back to the inlet of the combustor 10 and into the flame tube 40 together with fuel and air from the compressor 13 of the first gas turbine 12. The object of the re-circulation is to increase concentration of flue gas optimally before feeding the CO₂ enriched flue gas to the CO₂ membrane plant 11.

The steam from the heat recovery steam generators 17 and 18 drives a steam generator 26. In addition the heat recovery steam generator(s) 17,18 supply steam which is introduced into the cleaned flue gas upstream of the inlet to the jacket 27 surrounding the flame tube 40. The steam is introduced in order to compensate for the loss of volume caused by the removed CO₂. Steam may in addition or as an alternative be delivered as energy to an industrial plant.

FIG. 3 shows a corresponding solution to the embodiment shown on FIG. 2, the main and only difference being introduction of a unit for additional heating 28 into the pipe 29 after the exit from the jacket 27 and before the inlet to the turbine 14 in the first gas turbine plant. The unit for additional heating 28 is for example obtained by combustion of natural gas. Such unit for additional heating 28 increases the temperature of the cleaned flue gas from a typical temperature of approx. 800° C. or higher up to approx. 1200-1400° C. This will enhance the efficiency of the plant, but may reduce the degree of removed CO₂ from the power plant.

According to the embodiment shown in FIGS. 1-3 two different gas turbine plants with respect to output effect are employed, for example in the ratio 1:3. Other ratios may also be employed. Alternatively gas turbine plants having the same ratio may be employed, i.e. that any ratio between 1.3 and 1.1 with respect to output effect may be used. On the other hand, the other gas turbine parameters, such as for example the pressure ratio, should be approx. 1:1. Since gas turbine plants available on the market only are of standard models with respect to design and output effect, the process shown in FIG. 3 may be adjusted to given gas turbine plants.

The combined cycle gas turbines 12,12′ of the gas power plant may be of any standard type, the only possible exception being that the common combustor 10 may be modified compared with a standard combustor. It may be possible to modify different types of combustors, such as for example, but not limiting to, external combustors, silo type combustors or canned type combustors. In addition the integrated CO₂ capture plant 11 may be of the CO₂ membrane type, for example of the polymer type, and may be modified in order to obtain feasible and cost effective solutions.

Captioned CO₂ and possible nitrogen escaped through the CO₂ membrane may be removed from the CO₂ capture plant and for example be pumped back to the oil well in order to increase the oil production from the well (IOR=Increased Oil Recovery) or to a deposit plant of any suitable type.

Reference is made to FIG. 4 showing details of a preferred embodiment of a combustor 10 according to the invention. The combustor comprises a flame tube 40 and a surrounding casing or jacket 27. According to the process shown in FIGS. 1-3 a standard combustor 10 is used, modified to cater for the air management system according to the invention. The constructive solution of one embodiment of such standard combustor or combustion chamber may be found in available literature, textbooks and publications. It should be appreciated, however, that such standard combustor is commonly used in a different way since air commonly is circulated around the flame tube 40, between the jacket 27 and the flame tube 40, and then fed into the flame tube 40 at the combustion zone of the combustor.

According to the present invention the air management is different, since the combustor 10 is working primarily with to separate gas streams, one flowing internally through the flame tube 40 and the other flowing outside the flame tube 40. Only the gas stream passing within the interior of the flame tube 40 is fed to the CO₂ capture plant 11.

Compressed air from the compressor 13, natural gas and re-circulated flue gas from the combustor is fed into the flame tube 40 at one end 34 through the air supply pipe 31, the natural gas supply pipe 32 and the re-circulation pipe 33 for flue gas. The combusted flue gas leaves the burner 10 at its opposite end 35.

The cleaned flue gas is fed into the jacket 27 at the outlet end 35 of the combustor and circulated around the flame tube 40 at its exterior surface in order to cool down the flame tube, whereupon the cleaned flue gas leaves the jacket 27 in the area of the combustion zone of the flame tube 40. In such way the combustion in the combustor 10 may occur at optimal combustion temperature and air surplus in order to meet the requirements for a sufficiently low NO_(x) discharge.

In order to improve the supply of compressed air and re-circulated, un-cleaned flue gas the flame tube 40 may at the inlet end 34 of the combustor be provided with openings or inlet ducts 36. Ducts or tubes for circulation of flue gas may be arranged across the flame tube 40, preferably in diametrical direction, thereby increasing the degree of heat transfer and enabling use of known material technology for ducts in a combustor.

The combustor 10 according to the invention comprises thus a combination of a combustor and a heat exchanger. Hence, the combustion in the combustor 10 may occur at an optimal combustion temperature and with air surplus in order to meet the requirement of a sufficiently low NO_(x) discharge.

Although a plant using one single combustor is described, it should be appreciated that several combustors may be used. Further it should be appreciated that the combustor is shown schematically and further elements apparent for a person skilled in the art is incorporated but not shown or described. Examples of such omissions may inter alia be the pressure casing surrounding the combustor.

According to the embodiments shown and described above the CO₂ capture plant may for example be of the polymer type, and in particular a polymer membrane comprising cellulose acetate. Such types of membranes are both well proven and inexpensive in purchase and use, but have inherent limitations with respect to selectivity, since relatively larger volumes of nitrogen and oxygen may in addition to CO₂ escape through the membrane. It may, however, be feasible to use new types of polymer membranes for CO₂ capture without deviating from the inventive idea. Such new polymer membrane may make it feasible to employ higher inlet temperatures and thus reduce the need for gas-gas heat exchangers. 

1. Method for increasing energy and cost efficiency of a gas power plant or thermal power plant and for energy and cost effective CO₂ capture from a pressurized CO₂ enriched flue gas, said gas power plant or thermal power plant comprising one or more gas turbine plants or combined plant of steam and gas turbine cycles, comprising turbine(s) (12,12′) with compressor unit(s) (13,13′) and turbine(s) (14,14′) and further comprising a combustor (10), where the flue gas from the combustor (10) is cooled down and passes through a cleaning unit (11) where at least substantial portions of the CO₂ content is removed from the flue gas and where the cleaned flue gas is reheated and together with pressurized steam drives the turbine (14) where the steam is depressurized prior to being discharged to the atmosphere, charaterized in that the combustor (10) is working with mainly two separate gas part streams where one gas part stream goes internally in the flame tube (40) of the combustor (10) and where the other gas part stream passes along the exterior of the flame tube (40), the first gas part stream comprising additional air and re-circulated un-cleaned flue gas from the combustor being combusted together with fuel inside the flame tube (40), and the second gas part stream comprising cleaned flue gas which is heated up by the exterior of the flame tube (40) while the flame tube (40) being cooled down.
 2. Method according to claim 1, wherein the gas power plant being provided with a first (12) and a second (12′) gas turbine, each having a compressor unit (13,13′) and a turbine unit (14,14′), wherin the un-cleaned flue gas from the combustor (10) being compressed in the compressor unit (13′) of the second gas turbine plant (12′), the gas part stream of flue gas being cleaned and used for heat exchange in the combustor (10) in order to obtain optimal heating of this gas part stream in the combustor (10), transferrng the heat energy at highest possible temperature and where the cleaned gas part stream then is fed to the inlet of the turbine unit (14) of the first gas turbine plant (12) for driving said first gas turbine plant (12).
 3. Method according to claim 2, wherein the pressurized part of the flue gas to be cleaned is led through a CO₂ capture unit (11), for example of the polymer type, in order to remove CO₂ from the flue gas.
 4. Method according to claim 2, wherein steam is injected in the cleaned gas part stream before the inlet of the jacket (27) surrounding the flam tube (40) of the combustor (10), in order to compensate for removed CO₂ in the CO₂ capture plant (11) and in order to enhance the heat transfer in the combustor (10).
 5. Method according to claim 4, wherein one gas part stream from the compressor (13) is fed into the jacket (27) at the exit of the combustor (10) and exits the jacket (27) in the area of the combustion zone of the combustor (10).
 6. Method according to claim 1, wherein the other part of pressurized un-cleaned flue gas from the compressor unit (13′) is re-circulated back to the flame tube (40) together with pressurized air and fuel.
 7. Method according to claim 1, wherein the flue gas pressure is increased after expansion and cooling and wherein parts of the pressurized flue gas is re-circulated back to the combustor (10) in order to optimize enrichment of CO₂ prior to entering the CO₂ capture plant (11), preferably in the region of the combustion zone (39) of the combustor (10).
 8. Method according to claim 1, wherein water is removed from the flue gas in front of a booster (57), pressurizing the flue gas, whereupon water is added again after passing through the booster (57), thereby regulating the mole weight of flue gas at the inlet to the compressor (13′).
 9. Method according to claim 1, wherein the flue gas from the gas turbine plant(s) is fed through a heat recovery steam generator (17,18) for production of steam, where parts of the produced steam is fed back to the gas part stream in front of the jacket (47) of the combustor (10).
 10. Method according to claim 9, wherein the remaining parts of the produced steam drive one or more steam turbines (25).
 11. Method according to claim 1, wherein one part of the flue gas part stream is fed via a heat exchanger (19) to the CO₂ capture plant (11) whereupon the cleaned flue gas is returned back via the heat exchanger (19) where it is reheated and possibly mixed with steam and additional air from the compressor (13) of the first gas turbine plant (12), forming the gas part stream flowing along the exterior of the flame tube (40).
 12. Method according to claim 1, wherein a first and second gas turbine plant (12,12′), being coupled in series, are used and having common combustor(s) (10), the gas being heated at the exterior of the flame tube (40) and optionally being fed through a unit (28) for adding heat, is fed to the turbine unit (14) of the first gas turbine plant (12) and wherein the flue gas formed in the flam tube (40) being fed to the turbine unit (14′) of the second gas turbine plant (12′), whereupon the flue gas is fed to a heat recovery steam generator (18) where the flue gas is cooled and thereafter led via a water cooler (16) to the inlet of the compressor (13′) of the second gas turbine plant (12′) where the flue gas is compressed and split into two flue gas part streams.
 13. Method according to claim 12, wherein one flue gas stream is led via a heat exchanger (19) to the CO₂ capture plant (11) whereupon the cleaned flue gas is fed back via the heat exchanger (19) where the flue gas is reheated and then mixed with steam and thereafter circulated around the exterior of the flame tube (40).
 14. Power plant comprising at least one gas turbine plant or a combined cycle gas turbine plant, comprising at least to gas turbine plants (12,12′), each comprising a compressor unit (13,13′) and a turbine unit (14,14′), said heat power plant further comprises a combustor (10), a heat exchanger (19), a plant (11) for CO₂ capture from the flue gas from the combustor (10) and at least one heat recovery steam generator (17,18) and corresponding pipe line system between the various plants and units of the gas turbine plant, characterized in that a cleaned gas part stream from the flame tube (40) is feed through a pipe from the compressor unit (13′) of the gas turbine plant (12′) and injected steam to a jacket (27) surrounding the combustor (10) and led further through an exit pipe (29) from the jacket (27) to the inlet of a turbine unit (14) of the first gas turbine plant (12), the gas circulating through the jacket (27) being used for cooling of the combustor (10) in order to obtain optimal heating of such.
 15. Power plant according to claim 14, wherein the CO₂ capture plant (11) comprises a CO₂ membrane plant, preferably of the polymer type.
 16. Power plant according to claim 14, wherein a second un-cleaned gas part stream from the flame tube (40) is re-injected into the flame tube (40) together with additional air and fuel.
 17. Power plant according to claim 16, wherein the supply pipe for cleaned flue gas is coupled to the jacket (27) at the exit end of the combustor (10) while the outlet pipe (29) from the jacket (27) is arranged at the region of the combustion zone of the combustor (10).
 18. Power plant according to claim 15, wherein the turbine plant comprises two connected gas turbine plants where the first turbine plant (12) is driven by un-cleaned flue gas from the combustor (10), while the second gas turbine plant (12′) is driven by cleaned flue gas from the combustor (10), possible mixed with steam delivered from a steam delivery source (17,18) and air delivered by the compressor unit (13) of the first turbine plant (12).
 19. Combustor for use in a thermal or gas power plant comprising at least one gas turbine plant or a combined cycle gas turbine plant and further comprising a combustor (10) having a flame tube (40), a heat exchanger (19), a plant (11) for capture of CO₂ from the flue gas from the combustor (10) and at least one heat recovery steam generator (17,18) and corresponding pipe line system between the various units of the gas turbine plant, said combustor (10) comprising a combustion zone (39), pipe lines (31,32) for supply of air and fuel and an exit pipe (29) for exhaust gas at opposite end of the combustion zone (34), characterized in that a jacket (27) for circulation of a cooling gas is arranged around the flame tube (40), the inlet for the cooling gas being arranged in the region (35) of the exit pipe line (29) for flue gas while the exit from the jacket (27) is arranged in the region of the combustion zone (34), enabling the cooling gas to circulate through the jacket (27) in direction from the exit pipe (29)) for exhaust flue gas towards the combustion zone (34).
 20. Combustor according to claim 19, wherein the combustor (10) is provided with a supply line (33) for re-circulated exhaust gas. 